Lng Transportation Vessel and Method For Transporting Hydrocarbons

ABSTRACT

A vessel for transporting liquefied natural gas is provided. The vessel generally includes a gas transfer system for on-loading and off-loading natural gas to and from the vessel at essentially ambient temperature. The vessel further includes a gas processing facility for selectively providing liquefaction and regasification of the natural gas. The vessel also includes a containment structure for containing the liquefied natural gas during transport. The vessel may be a marine vessel or a barge vessel for transporting LNG over water, or a trailer vessel for transporting LNG overthe-road. A method for transporting LNG is also provided, that provides on-loading of natural gas onto a vessel, condensing the natural gas, storing the gas on the vessel in liquefied form, transporting the gas to an import terminal, vaporizing the gas, and off-loading the gas at the terminal.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application60/625,388, filed 5 Nov., 2004.

BACKGROUND

1. Field of the Inventions

Embodiments of the present invention generally relate to thetransportation of hydrocarbons. More particularly, embodiments of thepresent invention relate to an integrated design for a liquefied naturalgas transportation vessel. In addition, embodiments of the presentinvention relate to a method for combining liquefaction, transportationand regasification processes.

2. Description of Related Art

Clean burning natural gas has become the fuel of choice in manyindustrial and consumer markets around the world. However, natural gassources are often located in remote locations relative to the commercialmarkets desiring the gas. This means that the natural gas must sometimesbe produced in remote geographic locations, and then transported acrossoceans using large-volume marine vessels.

To maximize gas volumes for transportation, the gas may be taken througha liquefaction process. The liquefied natural gas (“LNG”) is formed bychilling very light hydrocarbons, e.g., gases containing methane, toapproximately −160° C. The liquefied gas may be stored at ambientpressure in special, cryogenic tanks disposed on large ships.Alternatively, LNG may be liquefied at an increased pressure and at awarmer temperature, i.e., above −160° C., in which case it is known asPressurized LNG (“PLNG”). For purposes of the present disclosure, PLNGand LNG may be referred to collectively as “LNG.”

The transportation of LNG to the importing nation or locale isexpensive. As currently developed, gas is taken through a liquefactionprocess at a location proximate the point of production. This means thata large gathering and liquefaction center is erected in the producingcountry. Alternatively, the liquefaction process may take place offshoreon a platform or vessel, such as a floating production, storage andoffloading (FPSO) vessel. From there, the hydrocarbon product is loadedin its liquefied state onto marine transport vessels. Such vessels areknown as LNG tankers.

Upon arrival at a destination country, the LNG product is offloaded at areceiving terminal. The receiving terminal may be onshore or “nearshore” relative to the importing nation. In some cases, the gas istemporarily maintained in storage in its chilled and liquefied state.Liquefaction enables larger volumes of gas to be stored in insulatedtanks until introduced into the gas grid, or delivered to a customer. Insome instances, the chilled gas is transported in specially insulatedvessels on the back of a trailer and hauled over-the-road to markets. Insome instances, the imported LNG is “vaporized” into the grid for themarket.

LNG technology generally requires large investments of capital andresources at the export and import terminals. It also requires cryogenictransfer of liquids at each end. In many locations, natural gasresources are present in insufficient quantities to justify the expenseof building a gas liquefaction processing facility in the producingcountry or at the producing site. In addition, the transfer of cryogenicmaterial, particularly from an FPSO, is difficult. Alternatively,consumer demand at the importing location may not economically justifythe fabrication of a regasification facility. Therefore, there is a needfor an integrated vessel that is capable of receiving a lighthydrocarbon product at an export terminal of a producing country,chilling the gas to a liquefied state, and then transporting the gas toa location in greater proximity to the desired market. In addition,there is a need for a vessel that is capable of regasifying the lighthydrocarbon upon arrival at a location for offloading, or importterminal. There is further a need for such a vessel that travels theoceans, on a river, or over the road.

Additional information relating to LNG liquefaction, transportation,and/or regasification technology can be found in U.S. Pat. No. 5,878,814(to Breivik et al.), DE 32 00 958 (Linde A G), U.S. Pat. No. 5,025,860(to Mandrin et al.), U.S. Pat. No. 6,517,286 (to Latchem), WO2004/081441 (Conversion Gas Imports), US2003/185631 (Bliault et al.), WO2004/000638 (ABB Lummus Global, Inc.), U.S. Pat. No. 3,766,583 (toPhelps), US2003/182948 (Nierenberg), US 2002/174662 (Frimm et al.), andU.S. Pat. No. 6,089,022 (to Zednik et al.).

SUMMARY

First, a method for transporting liquefied natural gas is provided. Themethod includes the steps of on-loading natural gas in a substantiallygaseous phase onto a vessel at a first location; cooling the natural gason the vessel so as to convert it substantially into liquefied naturalgas; storing the liquefied gas in an insulated container; transportingthe liquefied natural gas on the vessel from the first location to asecond location; heating the liquefied natural gas on the vessel so asto reconvert it back into a substantially gaseous phase; and off-loadingthe natural gas from the vessel at the second location. Preferably, thesteps of cooling the natural gas and heating the liquefied natural gasare each accomplished by using a gas processing facility. Morepreferably, the same gas processing facility is used for both cooling(liquefying) the natural gas and heating the liquefied natural gas.

The method for transporting LNG may be accomplished on a variety ofvessels. Examples include a marine vessel, a barge vessel, and anover-the-road trailer vessel.

In another aspect, a method is provided for transporting liquefiednatural gas on a vessel. The method generally comprises the steps ofproviding a gas transfer system for the vessel; on-loading the naturalgas onto the vessel through the gas transfer system, the natural gasbeing in essentially a gaseous phase; providing a gas processingfacility on the vessel, the gas processing facility selectively coolingand heating the natural gas; flowing the natural gas through the gasprocessing facility so as to cool the natural gas to a lower temperaturewhere the natural gas is in a substantially liquefied phase, andproviding a containment structure on the vessel for containing theliquefied natural gas during transport.

In addition, a vessel for transporting liquefied natural gas isprovided. In one embodiment, the vessel includes a gas transfer systemfor on-loading and off-loading natural gas to and from the vessel in itsessentially gaseous phase; a gas processing facility for selectively (i)cooling the natural gas from a temperature where the natural gas is in agaseous phase, to a lower temperature where the natural gas is in asubstantially liquefied phase; and (ii) heating the natural gas from atemperature where the natural gas is in a substantially liquefied phase,to a temperature where the natural gas is converted back to its gaseousphase; a power generator for providing power to the gas processingfacility; and a containment structure for containing the liquefiednatural gas during transport.

The vessel again may be any type of transport vessel, including forexample a marine vessel, a barge vessel, or an over-the-road trailervessel. Where the vessel is a marine vessel, the gas transfer system mayfurther comprise a buoyed line for placing the gas processing facilityin fluid communication with a marine jumper line. Where the vessel is aland-based vessel such as a vessel on a trailer, the gas transfer systemmay further comprise a line for placing the gas processing facility influid communication with a land hose.

Where the containment structure is a marine vessel, the containmentstructure may be one or more Moss sphere tanks, it may be a membranetank, or it may be a plurality of pressurized bottles in fluidcommunication. The plurality of bottles maintain the LNG under pressuresgreater than ambient.

In one aspect, the gas processing facility comprises at least one heatexchanger through which the natural gas thermally contacts a heatexchanger fluid; and at least one fluid movement device. The fluidmovement device may be either a compressor or a pump.

In one arrangement, the gas processing facility cools the natural gas byproviding a first heat exchanger for cooling the natural gas by thermalcontact between the natural gas and a heat exchanger fluid; a compressorwherein the heat exchanger fluid is compressed and temporarily warmedafter flowing through the first heat exchanger; a second heat exchangerwherein the compressed heat exchanger fluid is cooled; and an expanderwherein the compressed heat exchanger fluid is further cooled, anddecompressed before returning through the first heat exchanger.Alternatively, the gas processing facility heats the natural gas byproviding a first heat exchanger for warming the natural gas by thermalcontact between the natural gas and a heat exchanger fluid; and a secondheat exchanger wherein the heat exchanger fluid is warmed after flowingthrough the first heat exchanger. The heat exchanger fluid movementdevice may be a compressor wherein the heat exchanger fluid iscompressed and further warmed after flowing through the second heatexchanger and before returning through the first heat exchanger.Alternatively, the fluid movement device is a pump disposed in linebetween the first and second heat exchangers for pressurizing theliquefied heat exchanger fluid.

Preferably, the power generator is configured to selectively providepower to propel the vessel when the natural gas is stored in thecontainment structure, and to provide power to the gas processingfacility when the natural gas is being cooled or heated. Optionally, thevessel may further have an ancillary compressor for circulating andcooling the heat exchanger fluid while the vessel is transporting theLNG in order to recondense any natural gas that becomes vaporized duringtransport, or to generally keep the heat exchanger fluid and systemequipment cool.

BRIEF DESCRIPTION OF THE DRAWINGS

The following drawings are provided as an aid in understanding thevarious inventions described herein.

FIG. 1A presents a plan view of the main deck of a fluid transportationvessel. The exemplary vessel is a marine vessel. Visible in this vieware a bridge, a cargo storage area, and a gas processing facility. Thecargo storage area represents one or more individual tanks within aliquefied gas containment structure.

FIG. 1B presents an alternate marine vessel for transporting fluids in atemperature-controlled environment. The containment structure of the LNGtransportation vessel of FIG. 1B is a Moss sphere tank.

FIG. 1C presents yet an additional alternate marine vessel fortransporting fluids in a temperature-controlled environment. Thecontainment structure of the LNG transportation vessel of FIG. 1C is amembrane tank. The illustrative vessel is again a marine vessel.

FIG. 2 is a side view of the vessel of FIG. 1A. The profile of thevessel can be seen. Visible in this view is a side of the containmentstructure of FIG. 1A.

FIG. 3 presents a schematic view of the gas processing facility of FIG.1A, in one embodiment. Arrows depict the process of liquefaction for thelight hydrocarbons.

FIG. 4A presents another schematic view of the gas processing facilityof FIG. 1A. In this view, arrows depict the process of regasificationfor the light hydrocarbons.

FIG. 4B presents an alternate arrangement for the regasificationfacility of FIG. 4A. In this view, arrows again depict the process ofregasification for the light hydrocarbons.

FIG. 5A demonstrates an LNG transportation vessel as a barge vessel. Thebarge vessel is being towed by a tug boat.

FIG. 5B demonstrates the LNG transportation vessel as a trailer vessel.The trailer vessel is being pulled by an over-the-road rig.

DETAILED DESCRIPTION

The following words and phrases are specifically defined for purposes ofthe descriptions and claims herein. To the extent that a term has notbeen defined, it should be given its broadest definition that persons inthe pertinent art have given that term as reflected in printedpublications, dictionaries and/or issued patents.

“Natural gas” means a light hydrocarbon gas or a mixture including twoor more light hydrocarbon gases that includes greater than 25 molarpercent methane on a hydrocarbon species basis. For example, natural gasmay contain methane along with other hydrocarbon components such as, butnot limited to, ethane, propane, butane, or isomers thereof. Natural gasmay also include non-hydrocarbon contaminant species such as, forexample, carbon dioxide, hydrogen sulfide, water, carbonyl sulfide,mercaptans and nitrogen.

“LNG” or “liquefied natural gas” means natural gas or a portion thereofthat has been liquefied. The term collectively includes any lighthydrocarbon or mixture of two or more light hydrocarbons insubstantially liquid form that includes greater than 25 molar percentmethane on a hydrocarbon species molar basis. LNG includes, for example,natural gas induced into a liquid form through cooling at aboutatmospheric pressure and by both cooling and application of increasedpressure over ambient pressure such as “PLNG.”

“Vessel” means any fluid transportation structure. Non-limiting examplesof a vessel include a marine vessel, a barge vessel, or a trailervessel.

“Marine vessel” means a vessel configured to transport volumes of fluidssuch as LNG over an ocean or other large water body.

“Barge vessel” means a vessel configured to transport volumes of fluidssuch as LNG over a river or within a marine inlet or bay.

“Trailer vessel” means a vessel configured to transport volumes offluids such as LNG on a trailer. The trailer is pulled by a truck, arig, or other mechanized vehicle over-the-road.

The terms “on-loading” and “off-loading” refer to the movement of fluidsonto and off of a vessel, respectively. The terms are not limited as tothe manner in which fluid movement is accomplished.

“Gas transfer system” means a system for on-loading or off-loading offluids in at least a partially gaseous phase. Non-limiting examples offeatures for a gas transfer system include compressors, valves, conduitsand pumps.

“Ambient temperature” refers to the temperature prevailing at anyparticular location.

“Expander” means any device capable of reducing pressure in a fluidline, including but not limited to an expansion valve or turboexpander.

Some embodiments of the invention include apparatus and methods forliquefying natural gas. In some embodiments natural gas includes a lighthydrocarbon gas or a mixture including two or more light hydrocarbongases that includes greater than 25 molar percent methane.Alternatively, natural gas may include greater than 40 molar percentmethane or greater than 70 molar percent methane on a hydrocarbonspecies basis.

Some embodiments of the invention include apparatus and methods forliquefying natural gas to form LNG or regasifying LNG to reform naturalgas. In some embodiments LNG includes natural gas or a portion thereofthat has been liquefied. LNG may include any light hydrocarbon ormixture of two or more light hydrocarbons in substantially liquid formthat includes greater than 25 molar percent methane on a hydrocarbonspecies basis. Alternatively, LNG may include greater than 40 molarpercent methane or greater than 70 molar percent methane on ahydrocarbon species basis.

The following provides a description of specific embodiments shown inthe drawings:

FIG. 1A presents a plan view of a fluid transportation vessel 100. Theillustrative fluid transportation vessel 100 is a marine vessel. Thevessel 100 is specifically configured to carry liquefied natural gas, or“LNG,” over an ocean or other large water body. In one aspect, thevessel 100 is nominally 300 meters in length. The vessel 100 includes amain deck 12, visible in the plan view of FIG. 1A.

FIG. 2 provides a side view of the vessel 100 of FIG. 1A. A profile ofthe vessel 100 can be seen, defined by a hull 16. The hull 16 isgenerally under the main deck 12. The hull 16 provides for a“ship-shaped” vessel that is preferably self-propelled. However, it isunderstood that the scope of the present inventions is not limited tovessels that are ship-shaped or self-propelled.

The marine vessel 100 includes a bridge 20. The bridge 20 is typicallyat either the fore or aft sections of the vessel. The bridge 20 is seenin both FIGS. 1A and 2 at the bow of the ship 100. The bridge 20 ispositioned on the deck 12, and provides living quarters for the ship'sofficers and crew members. The bridge 20 also provides navigational andoperational controls for the ship 100. It is understood that the vesselwill also have a navigation system that will include a steering orguidance mechanism, a rudder and instrumentation (all not shown).

The marine vessel 100 further includes a cargo storage area 30, or“containment structure.” The containment structure 30 is shownschematically in FIGS. 1A and 2, and is intended to represent a single“insulated compartment.” The illustrative containment structure 30includes a plurality of containers 30A configured to hold a cryogenicfluid such as LNG under pressure. The containment structure 30 is cutaway in each of FIGS. 1A and 2 to expose a sampling of containers 30A.It is understood that the containment structure 30 is not limited to asingle “insulated compartment;” the containers 30A may be individuallyinsulated.

Selected sets of bottles 30A are in fluid communication with one anotherto form a “tank.” The bottles 30A have appropriate valving 32 for movingLNG into and out of the bottles 30A. In one aspect, four-inch pipingconnections are provided for moving cryogenic fluids into and out of thecontainers 30A, though it is understood that other dimensions may beemployed. The containers 30A may be at ambient pressure or slightlyhigher, and contain natural gas chilled to a temperature ofapproximately −160° F. (−106.7° C.) or less to provide liquefaction.Alternately the natural gas may be chilled to a temperature ofapproximately −190° F. (−123.3° C.) or less. Alternatively, thecontainers may be at ambient pressure or slightly higher, and containnatural gas chilled to a temperature of between approximately −200° F.to −270° F. (−128.9° C. to −167.8° C.). The containers 30A mayalternatively be stored at a higher pressure above approximately 150psi, and at temperature of approximately −193° F. (−125° C.) or more.Alternatively, the containers may be stored at a pressure in the rangeof approximately 250-450 psi, and at temperature between about −175° F.and −130° F. (−115° C. to −90° C.). Those of ordinary skill in the artwill understand that the liquefaction temperature of a hydrocarbon willdepend upon its pressure and composition.

The bottles 30A are preferably cylindrical in shape, and are typicallyfabricated from a steel material. Where the containers 30A serve as apressure vessel, they are preferably fabricated from a steel materialhaving walls of appropriate thickness. One or more bottles 30A in fluidcommunication together form a single “tank.”

Various other LNG containment structures are known for marine vessels.Examples are provided in FIGS. 1B and 1C. FIG. 1B presents a containmentstructure for an LNG transportation vessel 100B as a plurality of Mosssphere tanks 30B. The exemplary vessel 10 is again a marine vessel. TheMoss sphere tanks 30B are semispherical or elongated in shape, and mayhave a diameter of up to 40 or more meters. Typically, three to fiveMoss sphere tanks will be placed on a single marine vessel. LNG isstored in the Moss sphere tanks at ambient pressure.

FIG. 1C presents a containment structure 30C for an LNG transportationvessel 100C as a membrane tank. The exemplary vessel 100C is again amarine vessel. A membrane tank is typically a square or rectangularstructure having steel lining (not shown) for providing a fluid-tightcompartment. The lining is structurally supported by a frame that isinsulated. The framing forms an insulated cargo hold. Each membrane tank30C may be 40 meters×40 meters in footprint, for example.

Each illustrative marine vessel 100, 100B, 100C also includes a gasprocessing facility. The gas processing facility is shown schematicallyat 40, and is intended to represent any facility that can selectivelycool or heat fluids such as natural gas. Preferably, the gas processingfacility 40 will first cool the natural gas from an essentially ambienttemperature where the natural gas is in a gaseous phase, to a lowertemperature where the natural gas is in a substantially liquefied phase.This occurs in connection with a procedure for on-loading of natural gasonto the vessel, e.g., vessel 100. In addition, the gas processingfacility 40 will preferably also heat the natural gas from a temperaturewhere the natural gas is in a substantially liquefied phase, to anessentially ambient temperature where the natural gas is converted backto its gaseous phase. This occurs in connection with a procedure foroff-loading of natural gas from the vessel 100, 100B or 100C.

FIG. 3 presents a more detailed view of the gas processing facility 40,in one embodiment. In this view, the gas processing facility 40 is setup for the cooling of fluids, or “liquefaction.” Arrows depict the flowof fluids for the process of cooling the natural gas. More specifically,arrow G shows the movement of gas through the gas processing facility 40located on the vessel 100, while arrow C demonstrates the pumping of acoolant to cryogenically refrigerate the gas.

FIGS. 4A and 4B present other schematic views of the gas processingfacility 40 of FIGS. 1, 1B and 1C. In these views, the gas processingfacility 40 is set up for the heating of fluids, or “regasification.”Arrows depict the flow of fluids for a process of regasification oflight hydrocarbons. Arrow G shows the movement of gas through the gasprocessing facility 40 located on the vessel 100, while arrow Hdemonstrates the pumping of a heat exchanger fluid to warm the gas.FIGS. 4A and 4B provide alternate gas processing systems forregasification.

The gas processing facility of FIG. 3 is an intermediate facilitybetween the reception of natural gas from the field, and the storage ofLNG in the containment structure 30 for transport. Similarly, the gasprocessing facilities of FIGS. 4A and 4B each provide an intermediatefacility between the offloading of natural gas from the containmentstructure 30 to an import terminal. To accommodate the movement ofhydrocarbons onto and off of the vessel, a gas transfer system isprovided. The gas transfer system is represented schematically by line50 in FIGS. 3, 4A and 4B. In practice, the gas transfer system 50 willcomprise a line that provides fluid communication between the gasprocessing facility 40 and a line (not shown) external to the vessel100. For example, where the fluid transportation vessel is a marinevessel (such as the vessel 100 of FIG. 1A) or a barge vessel (seen inFIG. 5A), the line will connect to a marine jumper. The marine jumperwill preferably be buoyed with either integral or attached buoys. Wherethe fluid transportation vessel is a trailer vessel (seen in FIG. 5B),the line will connect to a land hose.

FIG. 5A demonstrates an LNG transportation vessel as a barge vessel500A. The barge vessel 500A is being towed by a tug boat 510A. Thevessel 500A includes a gas transfer system 502A, a gas processingfacility 504A, and a fluid containment structure 506A. The gas transfersystem 502A will typically define a hose configured to connect to amarine jumper line (not shown). The barge vessel 500A is preferablypulled by a tug 510A. The vessel 500A may be integral to the tug 510A,but is preferably a separate floating apparatus that can be hitched andunhitched. FIG. 5A shows a hitching line 501A. The tug 510A, of course,includes an engine and propeller (not shown). The engine is typicallydiesel or gasoline powered, and operates to drive the propeller in thewater W. The barge 510A may also include a battery (not shown) forpowering electrical equipment such as lights. Preferably, the gasprocessing facility 504A is powered by either the engine or the batteryof the tug 510A.

FIG. 5B demonstrates the LNG transportation vessel as a trailer vessel500B. The vessel 500B includes a gas transfer system 502B, a gasprocessing facility 504B, and a fluid containment structure 506B. Thegas transfer system 502B will typically define a valve and, perhaps, ahose configured to connect to a supply line (not shown). The trailervessel 500B is being pulled by an over-the-road rig 510B. The trailervessel 500B is disposed on a multi-axle trailer 520B for land-basedtransport.

The trailer vessel 500B is propelled by being pulled behind the rig510B, or “truck.” The vessel 500B may be integral to the truck 510B, butis preferably on a separate trailer 520B that can be hitched andunhitched. The truck 510B, of course, includes an engine and shaft (notshown). The engine is typically diesel or gasoline powered, and operatesto drive a shaft that transmits rotational motion to a transmission. Thetruck 510B also includes a battery (not shown) for powering electricalequipment. Preferably, the gas processing facility 504B is powered bythe engine of the truck 510B, reducing equipment requirements. Theengine may drive an electrical generator for creating electrical powerfor the gas processing facility 504B.

In practice, a volume of fluid such as natural gas is brought from thefield to a gathering center. The gathering center may be on land, nearshore, or offshore. The natural gas is stored at an essentially ambienttemperature. In the case of a marine vessel such as vessels 100, 100B,and 100C, the vessel is offshore and receives natural gas pumped fromthe gathering facility (not shown) onto the vessel through the gastransfer system 50. The natural gas is not stored directly in thecontainment structure 30 of the vessel 100; rather, it is pumped throughthe gas processing facility 40 for liquefaction in accordance with FIG.3.

Referring again to FIG. 3, a gas process facility 40 is again shown. Thegas process facility 40 is used for the purpose of condensing a fluid,such as natural gas. Arrow G depicts the flow of gas duringliquefaction, as described above.

The gas process facility 40 includes a first heat exchanger 42. Thefirst heat exchanger 42 acts to cool the natural gas by thermal contactbetween the natural gas and a heat exchanger fluid. The first heatexchanger 42 provides suitable adjacent fluid channels (not shown) fordirecting hydrocarbons and a heat exchanger fluid, respectively, so thatthe two channels are in thermal contact with one another. In thissequence, the heat exchanger fluid acts as a refrigerant flowing throughlines “C.”

The gas process facility 40 also includes a compressor 44. Thecompressor 44 receives the heat exchanger fluid, or refrigerant, as itcycles from the first heat exchanger 42, and compresses the refrigerant.The process of compressing the refrigerant also acts to temporarily warmthe refrigerant as it moves through the compressor 44. In onearrangement, the refrigerant is approximately 35° F. (1.7° C.) uponexiting the first heat exchanger 42, and is 300° F. (148.9° C.) uponexiting the compressor 44.

The gas process facility 40 also includes a second heat exchanger 46.The compressed refrigerant is cooled in the second heat exchanger 46.The second heat exchanger 46 provides adjacent fluid channels (notshown) through which the refrigerant and a coolant fluid flow. Thecoolant fluid acts to chill the refrigerant through thermal contact. Inthe context of a marine vessel such as the vessel 100 of FIG. 1A, thecoolant may be the abundantly available sea water or air. In the contextof a barge vessel (such as vessel 500A seen in FIG. 5A), the coolant maybe fresh water or air. In the context of a trailer vessel (such asvessel 500B seen in FIG. 5B), the coolant is most typically air.

The gas process facility 40 also includes an expander 48. The expander48 acts to expand the compressed refrigerant. The expander 48 may be anexpansion valve, a turboexpander, or any other device for expandingfluid. The process of expanding the compressed refrigerant acts not onlyto decompress the refrigerant, but also to further chill it. In onearrangement, the refrigerant is at a temperature of approximately 65° F.upon exiting the second heat exchanger 46, but is −170° F. upon exitingthe expander 48. The significantly chilled refrigerant is then cycledback through the first heat exchanger 42 where it again acts torefrigerate the natural gas. Ultimately, the natural gas is condensedinto a substantially liquid phase. Thus, the gas process facility 40 ofFIG. 3 acts as a liquefaction facility.

Referring now to FIG. 4A, the gas process facility 40 is again shown.However, in this arrangement the gas process facility 40 is used for thepurpose of heating a fluid, such as natural gas. Arrow G depicts theprocess of regasification for the light hydrocarbons as described above.The arrows are generally directed in opposite directions from the arrowsof FIG. 3.

The gas process facility 40 again includes a first heat exchanger 42. Inthis instance, however, the first heat exchanger 42 acts to warm thenatural gas by thermal contact between the natural gas and the heatexchanger fluid. In this sequence, the heat exchanger fluid acts as aheating fluid flowing through lines “H.” The first heat exchanger 42provides suitable fluid channels (not shown) for directing natural gasin its liquid phase, and a heat exchanger fluid, so that the twochannels are in thermal contact with one another. In this sequence, theheat exchanger fluid acts as a heating fluid.

After cycling through the first heat exchanger 42, the heat exchangerfluid moves to the second heat exchanger 46. The heat exchanger fluidbypasses the expander 48. It can be seen in FIG. 4A that the arrows donot indicate the flow of fluids through the expander 48.

In the regasification process shown in FIG. 4A, the second heatexchanger 46 now acts to warm the heat exchanger fluid. In this respect,the process of cycling the heat exchanger fluid through the first heatexchanger 42 has produced a cooling of the heat exchanger fluid. Theheat exchanger fluid is now very cold upon exiting the exchanger 42.Thus, the heat exchanger fluid is warmed in the second heat exchanger46. The second heat exchanger 46 provides adjacent fluid channels (notshown) through which the heat exchanger fluid and a warming fluid flow.The warming fluid acts to warm the heat exchanger fluid through thermalcontact. In the context of a marine vessel such as the vessel 100 ofFIG. 1A, the warming fluid may be sea water. Alternatively, the warmingfluid is fresh water maintained on the vessel at ambient temperature bya combustion or other warming process not shown. Alternatively, thesecond heat exchanger 46 may be a tank which receives and heats freshwater directly, such as through combustion. In the context of a bargevessel (such as vessel 500A seen in FIG. 5A), or in the context of atrailer vessel (such as vessel 500B seen in FIG. 5B), the warming fluidmay be either air or water.

From the second heat exchanger 46, the heat exchanger fluid movesthrough the compressor 44. The compressor 44 compresses the heatingfluid, and delivers it to the first heat exchanger 42 in a furtherwarmed state. As noted above, the process of compressing the fluid alsoacts to warm the fluid as it moves through the compressor 44. In onearrangement, the heat exchanger fluid is approximately 55° F. uponexiting the second heat exchanger 46, but is approximately 300° F. uponexiting the compressor 44. The significantly warmed heat exchanger fluidis then cycled back through the first heat exchanger 42 where it againacts to warm the natural gas. Ultimately, the natural gas is vaporizedinto a substantially gaseous phase for offloading. Thus, the gas processfacility 40 of FIG. 4 acts as a regasification facility.

Specific temperatures have been provided in connection with certaincomponents of the gas process facility 40. However, it is understoodthat the scope of the present inventions is not limited to anyparticular temperatures, so long as the temperature of the heatexchanger fluid as it enters the first heat exchanger is sufficientlylow to liquefy the natural gas (or other fluid) in the liquefactionprocess, and sufficiently high to vaporize the natural gas (or otherfluid) in the gasification process. It is noted, however, that the gasprocessing facility 40 operates more efficiently where water isavailable in the second heat exchanger 46 that is warm, i.e., fivedegrees Fahrenheit or more above freezing. In an environment that lacksa suitable ambient temperature warming medium, integration of theliquefaction and vaporization heat exchangers is difficult. In thisscenario, the gas processing facility 40 would preferably employ avaporization means heated through combustion of a portion of the naturalgas product. The fired vaporization facilities would benefit from theintegration of utilities like water supply and fuel gas systems with theliquefaction process.

As noted above, FIG. 4B presents an alternate arrangement for the gasprocessing facility of FIG. 4A. In this view, arrows again depict theprocess of regasification for the light hydrocarbons. The system is nowshown at 40′. In the arrangement of FIG. 4B, the heat exchanger fluid isagain cycled through the first heat exchanger 42 in order to warm(“regasify”) the LNG. The regasified hydrocarbons exit the gasprocessing facility 40′ through line 50. Ultimately, the natural gas isvaporized into a substantially gaseous phase for offloading. Thus, thegas process facility 40′ of FIG. 4B also acts as a regasificationfacility.

The process of cycling the heat exchanger fluid through the first heatexchanger 42 has produced a cooling of the heat exchanger fluid,substantially liquefying it. To reheat the heat exchanger fluid, theheat exchanger fluid is first moved through a pump 49. The pump 49serves as an alternate fluid movement device vis-à-vis the compressor44. It can again be seen that the heat exchanger fluid again bypassesthe expander 48. The pump 49 is provided after the first 42 heatexchanger in order to energize and warm the heat exchanger fluid. Thepump 49 also transfers the liquid heat exchanger fluid, e.g., sea water,towards the second heat exchanger 46.

As with facility 40 of FIG. 4A, the second heat exchanger 46 acts tofurther warm the heat exchanger fluid. The second heat exchanger 46provides adjacent fluid channels (not shown) through which the heatexchanger fluid and a warming fluid flow. The warming fluid acts to warmthe heat exchanger fluid through thermal contact. In the context of amarine vessel such as the vessel 100 of FIG. 1A, the warming fluid mayagain be seawater or fresh water that has been warmed through a directcombustion process. In the context of a barge vessel (such as vessel500A seen in FIG. 5A), or in the context of a trailer vessel (such asvessel 500B seen in FIG. 5B), the warming fluid may be either air orwater.

From the second heat exchanger 46, the heat exchanger fluid returnsdirectly to the first heat exchanger 42 where it again acts to warm thenatural gas. It can be seen that the compressor 44 has been bypassed inFIG. 4B. The compressor 44 is optionally not used when a pump 49 isemployed. The process of pumping the fluid through pump 44 provides thepressure needed to cycle the heat exchanger fluid through the system40′.

It can be seen from the arrangements of FIGS. 3, 4A and 4B thatsubstantially the same physical equipment and heat exchange fluids forboth the liquefaction operation and the regasification operation may beemployed. By modifying the refrigeration system operation as shown inFIG. 3, it is possible to use the same heat exchangers and heat transferfluids for vaporization of the gas via systems 40, 40′ of FIGS. 4A and4B. This results in equipment savings on the vessel. Where the vessel isa marine vessel, if the water temperature at the import location iswarm, i.e., approximately five degrees Fahrenheit or more abovefreezing, or if ambient heating medium of any type is available from asource near the import location, it is possible to install theliquefaction and regasification equipment 40 on the vessel, e.g., vessel100, in a more cost-effective manner.

In the gas process facility 40 shown in FIGS. 3 and 4A, the heatexchanger fluid is moved through the system 40 by compression.Compression may be accomplished by using the compressor 44 as the fluidmovement device. In the gas process facility 40′ shown in FIG. 4B, theheat exchanger fluid is moved through the system by pumping. Pumping maybe accomplished in connection with pump 49 as the fluid movement device.Power is provided to either the compressor 44 or the pump 49 (and othermechanical parts of the gas process facilities 40 and 40′) by a powergenerator. A power generator is shown schematically at 41 in FIGS. 3, 4Aand 4B.

The power generator 41 is preferably an engine. The engine may begas-powered, with the gas being provided from either naturally-occurringboil-off of natural gas from the LNG stored in the containment structure30, or from an independent fuel supply (not shown). Alternatively, theengine may be diesel powered. In this instance, a diesel supply (notshown) would be provided on the ship. In the arrangement of FIGS. 3 and4A, it can be seen that the power generator 41 drives a motor 43 m.Arrow “e” indicates an electric line providing power to the motor 43 m.The motor 43 m in turn, provides mechanical power to run the vessel'spropulsion system, shown schematically at 43. Arrow “s” is indicative ofa mechanical shaft going to the propulsion system 43.

It is preferred that the ship's propulsion system 43 be integrated withthe power system for powering the gas processing facility 40 or 40′.Thus, when the ship is not in transit, the power generator may be usedto drive separate motors 44 m and 49 m (49 m not shown). The motors 44 mand 49 m, in turn, provide mechanical power to either the compressor 44(in the arrangement of FIGS. 3 and 4A and B) or the pump 49 (in thearrangement of FIG. 4B), respectively.

In order for the gas processing facility 40 to share a power generator41 with the ship's propulsion system 43, the power requirements shouldbe generally comparable. With propulsion and gas processing powerrequirements being comparable, a single, integrated power generationplant and electric or hydrocarbon motor drive may be installed toprovide the power needed for both operations. In this arrangement, thegas compression 44 and ship propulsion 43 are preferably not used at thesame time so as to minimize the overall power generation needs for theship. In one embodiment, the power generator 41 is a power generationplant that feeds a single variable frequency drive (VFD). The VFD isused to alternately control the ship's propulsion 43 and to powerrefrigeration motors 44 m and 49 m. It is understood that the presentinventions are not limited to the way in which power is shared ortransferred between the propulsion system 43 and the gas processingfacility 40. Other power arrangements may be used, such as themodification of motor windings, or the use of a gear box system thatemploys mechanical shafts.

In another embodiment, the ship's power generator 41 may be used forinitial liquefaction of the natural gas, as described above inconnection with FIG. 3. However, a smaller separate compressor 45 mayoptionally be provided to provide power to the gas processing facility40 during the transport stage. In this respect, natural gas thatvaporizes during transport due to an increase in temperature within thecontainment structure 30 would be captured in the first heat exchanger42. The compressor 45 would be activated by an ancillary smaller motor45 m to temporarily operate the condensing process in order to re-coolthe natural gas without interrupting the ship's propulsion power 43. Theancillary motor 45 m draws a smaller amount of power from the powergenerator 41. An electric line “e” is shown between the power generator41 and the smaller generator 45 m. Further, a mechanical shaft “s” isshown going into the compressor 45. Finally, a bypass loop “b” isprovided to circulate heat exchanger fluid through the smallercompressor 45 rather than the primary compressor 44.

The use of a smaller, ancillary compressor 45 has many advantages.First, this arrangement allows reliquefaction of hydrocarbons duringtransit. This, in turn, accommodates a much higher boil-off gas ratefrom the containment structure 30. This also reduces the insulationrequirements for the cryogenic storage. Further, the use of a smaller,ancillary compressor 45 keeps the heat exchanger fluid and systemequipment cold during transit, allowing the vessel to be prepared morequickly to receive natural gas more quickly upon docking at an exportterminal for liquefaction.

In yet another embodiment, two independent power generation systems areprovided. One system operates to power the ship's propulsion system 43,while the other system operates the gas processing facility 40 alongwith the miscellaneous process equipment associated with liquefactionand vaporization. Such process equipment may include firefightingequipment, gas processing controls, fluid pumps, and drain valves.

A method for transporting liquefied natural gas on a vessel is alsoprovided. The vessel may be a marine vessel such as vessel 100 of FIG.1A, a barge vessel such as vessel 500A of FIG. 5A, or a trailer vesselsuch as vessel 500B of FIG. 5B. A gas transfer system, such as system 50of FIG. 3, is provided on the vessel. Further, a containment structureis provided on the vessel for containing the liquefied natural gas. Thecontainment structure may be, by example, one of the structures shown inFIG. 1A, 1B, 1C, 5A or 5B. In addition, a gas processing facility isprovided on the vessel. The gas processing facility may be such asfacility 40 of FIGS. 3 and 4A or facility 40′ of FIG. 4B, and mayselectively cool and heat the natural gas.

As part of the method, the natural gas is on-loaded onto the outfittedvessel at an export terminal. The natural gas is on-loaded through a gastransfer system at essentially ambient temperature and in a gaseousphase. The transport vessel may optionally be integrated with thenatural gas production system. The transport vehicle would receive rawfluids from the well, and provide the facilities to process the fluidsinto gas, ambient hydrocarbon liquid, and produced water. The productionfacilities would receive utility and operating benefits throughintegration with the liquefaction and vaporization facilities. Thetransport vehicle would also have the storage capacity to transport anddeliver any ambient liquid hydrocarbon products created in theproduction system.

The natural gas flows through the first heat exchanger 42 of the gasprocessing facility 40 so as to cool the natural gas from its ambienttemperature. The natural gas is brought to a lower temperature where itis in a substantially liquefied phase. Thus, the natural gas is“liquefied.” The liquefied natural gas is then stored in the containmentstructure 30, and is ready for transport on the vessel to an importterminal.

During the on-loading process, the ship's propulsion system 43 ispreferably shut down. The ship's power generator 41 diverts power to theliquefaction process facilities 40. Once the ship cargo is full, the gasprocessing system 40 is shut down, and the ship propulsion system 43 isstarted. The vessel 100 then transports the cryogenic cargo to theimport location.

Upon arrival at an import terminal, the gas is off-loaded. In order tooff-load the gas, the gas is pumped through the gas processing facility40 so as to heat the natural gas from a temperature where the naturalgas is in its substantially liquefied phase, to a temperature where thenatural gas is converted back to its gaseous phase. The natural gas isthen off-loaded through the gas transfer system 50. While on station atthe import location, the ship's propulsion system 43 is again shut down,and the cryogenic cargo is regasified as it is unloaded from the vessel100. This allows for optionally an integrated power generator for boththe ship's propulsion system 43 and the gas processing facility 40.

In one embodiment of the method invention, partially regasified fluidsare pumped into a gas storage device on land. An example is a salt domecavern facility. The gas storage device is integrated with the vessel tostore pressurized gas off-loaded at the gas receiving terminal. Thefacility can be sized to supply continuous gas at the average deliveryrate between deliveries. Pressurized gas storage is ideal because thecryogenic fluid can be inexpensively pumped to storage pressures beforevaporization rather than having expensive gas compression with thestorage facility.

It can thus be seen that an LNG transportation vessel is provided, andthat a method for transporting LNG or other hydrocarbon fluids is alsoprovided. The method of transporting, in one aspect, combinesliquefaction, transportation and regasification processes. In addition,it can be seen that an integrated system is provided for transportingnatural gas.

Conventional gas transportation means require large transfer rates overa period of 25-30 years to be economically attractive. As a result, manyresources containing under approximately 5 TSCF (trillion standard cubicfeet) of gas currently go undeveloped. The disclosed technology mayallow an investor to monetize these smaller hydrocarbon reserves. Thethree functions of liquefaction, transport and regasification may beintegrated into a single re-deployable unit for cost-effective transportof natural gas to consumer markets from remote locations. Stated anotherway, the integration of liquefaction, vaporization and transport meansenables recovery of otherwise stranded hydrocarbon resources, and alsodecreases the overall manpower required for operations and maintenance,thus reducing operating expenses and crew requirements. The vesselallows monetization of small gas resources, and enables development of aseries of small resources as it is re-deployable.

1. A method for transporting liquefied natural gas, comprising:on-loading natural gas in a substantially gaseous phase onto a vessel ata first location; cooling the natural gas on the vessel so as to convertit substantially into liquefied natural gas; storing the liquefied gasin an insulated container; transporting the liquefied natural gas on thevessel from the first location to a second location; heating theliquefied natural gas on the vessel so as to reconvert it back into asubstantially gaseous phase; and off-loading the natural gas from thevessel at the second location.
 2. The method of claim 1, wherein thesteps of cooling the natural gas and heating the liquefied natural gasare each accomplished by using a gas processing facility.
 3. The methodof claim 2, wherein the same gas processing facility is used for bothcooling the natural gas and heating the liquefied natural gas.
 4. Themethod of claim 1, wherein the vessel is a marine vessel.
 5. The methodof claim 1, wherein the vessel is a barge vessel.
 6. The method of claim1, wherein the vessel is an over-the-road trailer vessel.
 7. The methodof claim 1, wherein the step of cooling the natural gas is accomplishedby using a gas processing facility which comprises: a first heatexchanger for cooling the natural gas by thermal contact between thenatural gas and a heat exchanger fluid; a compressor wherein the heatexchanger fluid is compressed and temporarily warmed after flowingthrough the first heat exchanger; a second heat exchanger wherein thecompressed heat exchanger fluid is cooled; and an expander wherein thecompressed heat exchanger fluid is further cooled, and decompressedbefore returning through the first heat exchanger.
 8. The method ofclaim 1, wherein the step of heating the natural gas is accomplished byusing a gas processing facility which comprises: a first heat exchangerfor warming the natural gas by thermal contact between the natural gasand a heat exchanger fluid; a second heat exchanger wherein the heatexchanger fluid is warmed after flowing through the first heatexchanger; and a heat exchanger fluid movement device.
 9. The method ofclaim 8, wherein the heat exchanger fluid movement device comprises: acompressor wherein the heat exchanger fluid is compressed and furtherwarmed after flowing through the second heat exchanger and beforereturning through the first heat exchanger.
 10. The method of claim 8,wherein the fluid movement device comprises: a pump disposed in linebetween the first and second heat exchangers for pressurizing theliquefied heat exchanger fluid.
 11. The method of claim 8, wherein thesecond heat exchanger heats the heat exchanger fluid by providingthermal contact between the heat exchanger fluid and sea water atambient ocean temperature.
 12. The method of claim 8, wherein the secondheat exchanger heats the heat exchanger fluid by providing thermalcontact between the heat exchanger fluid and air.
 13. The method ofclaim 8, wherein the heat exchanger fluid is heated by thermal contactwith an intermediate fluid that itself is heated by a combustion sourceoutside of the second heat exchanger.
 14. The method of claim 8, whereinthe second heat exchanger heats the heat exchanger fluid by providingthermal contact between the heat exchanger fluid and a combustionsource.
 15. The method of claim 7, wherein the heat exchanger fluidcomprises a light hydrocarbon.
 16. The method of claim 8, wherein theheat exchanger fluid comprises a light hydrocarbon.
 17. The method ofclaim 1, wherein the steps of cooling the natural gas and heating theliquefied natural gas are each accomplished by using a single gasprocessing facility that: (a) cools the natural gas by providing: afirst heat exchanger for cooling the natural gas by thermal contactbetween the natural gas and a heat exchanger fluid, the heat exchangerfluid acting as a refrigerant; a compressor wherein the refrigerant iscompressed and temporarily warmed after flowing through the first heatexchanger; a second heat exchanger wherein the compressed refrigerant iscooled; and an expander wherein the compressed refrigerant is furthercooled, and decompressed before returning through the first heatexchanger; and (b) heats the natural gas by providing: the first heatexchanger for warming the natural gas by thermal contact between thenatural gas and the heat exchanger fluid; the second heat exchangerwherein the heat exchanger fluid is warmed after flowing through thefirst heat exchanger; and a fluid movement device.
 18. The method ofclaim 17, wherein the fluid movement device comprises: the compressor,wherein the heat exchanger fluid is compressed and further warmed afterflowing through the second heat exchanger and before returning throughthe first heat exchanger.
 19. The method of claim 17, wherein the fluidmovement device comprises: a pump disposed in line between the first andsecond heat exchangers for pressurizing the liquefied heat exchangerfluid.
 20. The method of claim 17, wherein the heat exchanger fluid thatcools the natural gas and the heat exchanger fluid that heats thenatural gas are at least partially different.
 21. A method fortransporting liquefied natural gas on a vessel, comprising: providing agas transfer system for the vessel; providing a gas processing facilityon the vessel, the gas processing facility selectively cooling andheating the natural gas; on-loading the natural gas onto the vesselthrough the gas transfer system, the natural gas being in essentially agaseous phase; and flowing the natural gas through the gas processingfacility so as to cool the natural gas to a lower temperature where thenatural gas is in a substantially liquefied phase; and providing acontainment structure on the vessel for containing the liquefied naturalgas during transport.
 22. The method of claim 21, further comprising thestep of: pumping the natural gas through the gas processing facility soas to heat the natural gas from a temperature where the natural gas isin its substantially liquefied phase, to a temperature where the naturalgas is at least partially converted back to its gaseous phase; andoff-loading the natural gas from the vessel through the gas transfersystem.
 23. The method of claim 21, wherein the vessel is a marinevessel.
 24. The method of claim 21, wherein the vessel is a bargevessel.
 25. The method of claim 21, wherein the vessel is anover-the-road trailer vessel.
 26. The method of claim 21, wherein thegas transfer system comprises: a connection for receiving a buoyed line,thereby placing the gas processing facility in fluid communication witha marine jumper line.
 27. The method of claim 21, wherein the gastransfer system comprises: a connection for receiving a line for placingthe gas processing facility in fluid communication with a hose.
 28. Themethod of claim 21, wherein the containment structure is a plurality ofpressure vessels for maintaining the liquefied natural gas underpressure.
 29. The method of claim 21, wherein: the containment structureis one or more Moss sphere tanks.
 30. The method of claim 21, whereinthe containment structure is a membrane tank.
 31. The method of claim21, wherein the gas processing facility comprises: at least one heatexchanger through which the natural gas thermally contacts a heatexchanger fluid; and at least one compressor for compressing the heatexchanger fluid.
 32. The method of claim 21, wherein the gas processingfacility cools the natural gas by providing: a first heat exchanger forcooling the natural gas by thermal contact between the natural gas and aheat exchanger fluid; a compressor wherein the heat exchanger fluid iscompressed after flowing through the first heat exchanger; a second heatexchanger wherein the compressed heat exchanger fluid is cooled; and anexpander wherein the compressed heat exchanger fluid is decompressed,and further cooled before returning through the first heat exchanger.33. The method of claim 21, wherein the gas processing facility heatsthe natural gas by providing: a first heat exchanger for warming thenatural gas by thermal contact between the natural gas and a heatexchanger fluid; a second heat exchanger wherein the heat exchangerfluid is warmed after flowing through the first heat exchanger; and afluid movement device.
 34. The method of claim 33, wherein the fluidmovement device comprises: a compressor wherein the heat exchanger fluidis compressed and further warmed after flowing through the second heatexchanger and before returning through the first heat exchanger.
 35. Themethod of claim 33, wherein the fluid movement device comprises: a pumpdisposed in line between the first and second heat exchangers forpressurizing the liquefied heat exchanger fluid.
 36. The method of claim33, wherein the second heat exchanger heats the heat exchanger fluid byproviding thermal contact between the heat exchanger fluid and sea waterat ambient ocean temperature.
 37. The method of claim 33, wherein thesecond heat exchanger heats the heat exchanger fluid by providingthermal contact between the heat exchanger fluid and air.
 38. The methodof claim 33, wherein the second heat exchanger heats the heat exchangerfluid by providing thermal contact between the heat exchanger fluid anda combustion source.
 39. The method of claim 33, wherein the heatexchanger fluid is heated by thermal contact with an intermediate fluidthat itself is heated by a combustion source outside of the second heatexchanger.
 40. The method of claim 21, wherein the gas processingfacility: (a) cools the natural gas by providing: a first heat exchangerfor cooling the natural gas by thermal contact between the natural gasand a heat exchanger fluid, the heat exchanger fluid acting as arefrigerant; a compressor wherein the refrigerant is compressed andtemporarily warmed after flowing through the first heat exchanger; asecond heat exchanger wherein the compressed refrigerant is cooled; andan expander wherein the compressed refrigerant is further decompressedand cooled before returning through the first heat exchanger; and (b)heats the natural gas by providing: the first heat exchanger for warmingthe natural gas by thermal contact between the natural gas and the heatexchanger fluid; the second heat exchanger wherein the heat exchangerfluid is warmed after flowing through the first heat exchanger; and thecompressor wherein the heat exchanger fluid is compressed and furtherwarmed after flowing through the second heat exchanger and beforereturning through the first heat exchanger.
 41. The method of claim 40,wherein the heat exchanger fluid that cools the natural gas and the heatexchanger fluid that heats the natural gas are at least partiallydifferent.
 42. A vessel for transporting liquefied natural gas,comprising: a gas transfer system for on-loading and off-loading naturalgas to and from the vessel in its essentially gaseous phase; a gasprocessing facility for selectively (i) cooling the natural gas from atemperature where the natural gas is in a gaseous phase, to a lowertemperature where the natural gas is in a substantially liquefied phase;and (ii) heating the natural gas from a temperature where the naturalgas is in a substantially liquefied phase, to a temperature where thenatural gas is converted back to its gaseous phase; a power generatorfor providing power to the gas processing facility; and a containmentstructure for containing the liquefied natural gas during transport. 43.The vessel of claim 42, wherein the vessel is a marine vessel.
 44. Thevessel of claim 42, wherein the vessel is a barge vessel.
 45. The vesselof claim 42, wherein the vessel is an over-the-road trailer vessel. 46.The vessel of claim 42, wherein the gas transfer system comprises: abuoyed line for placing the gas processing facility in fluidcommunication with a marine jumper line.
 47. The vessel of claim 42,wherein the gas transfer system comprises: a line for placing the gasprocessing facility in fluid communication with a hose.
 48. The vesselof claim 42, wherein the containment structure is a plurality ofpressure vessels for maintaining the liquefied natural gas underpressure.
 49. The vessel of claim 42, wherein: the containment structureis one or more Moss sphere tanks.
 50. The vessel of claim 42, whereinthe containment structure is a membrane tank.
 51. The vessel of claim42, wherein the gas processing facility comprises: at least one heatexchanger through which the natural gas thermally contacts a heatexchanger fluid; and a fluid movement device for moving the heatexchanger fluid.
 52. The vessel of claim 42, wherein the gas processingfacility cools the natural gas by providing: a first heat exchanger forcooling the natural gas by thermal contact between the natural gas and aheat exchanger fluid; a compressor wherein the heat exchanger fluid iscompressed and temporarily warmed after flowing through the first heatexchanger; a second heat exchanger wherein the compressed heat exchangerfluid is cooled; and an expander wherein the compressed heat exchangerfluid is decompressed and further cooled before returning through thefirst heat exchanger.
 53. The vessel of claim 42, wherein the gasprocessing facility heats the natural gas by providing: a first heatexchanger for warming the natural gas by thermal contact between thenatural gas and a heat exchanger fluid; a second heat exchanger whereinthe heat exchanger fluid is warmed after flowing through the first heatexchanger; and a fluid movement device.
 54. The vessel of claim 53,wherein the fluid movement device comprises: a compressor wherein theheat exchanger fluid is compressed and further warmed after flowingthrough the second heat exchanger and before returning through the firstheat exchanger
 55. The vessel of claim 53, wherein the fluid movementdevice comprises: a pump disposed in line between the first and secondheat exchangers for pressurizing the liquefied heat exchanger fluid. 56.The vessel of claim 53, wherein the second heat exchanger heats the heatexchanger fluid by providing thermal contact between the heat exchangerfluid and sea water at ambient ocean temperature.
 57. The vessel ofclaim 53, wherein the second heat exchanger heats the heat exchangerfluid by providing thermal contact between the heat exchanger fluid anda combustion source.
 58. The method of claim 53, wherein the heatexchanger fluid is heated by thermal contact with an intermediate fluidthat itself is heated by a combustion source outside of the second heatexchanger.
 59. The vessel of claim 42, wherein the gas processingfacility: (a) cools the natural gas by providing: a first heat exchangerfor cooling the natural gas by thermal contact between the natural gasand a heat exchanger fluid, the heat exchanger fluid acting as arefrigerant; a compressor wherein the refrigerant is compressed andtemporarily warmed after flowing through the first heat exchanger; asecond heat exchanger wherein the compressed refrigerant is cooled; andan expander wherein the compressed refrigerant is decompressed andfurther cooled before returning through the first heat exchanger; and(b) heats the natural gas by providing: the first heat exchanger forwarming the natural gas by thermal contact between the natural gas andthe heat exchanger fluid; the second heat exchanger wherein the heatexchanger fluid is warmed after flowing through the first heatexchanger; and the compressor wherein the heat exchanger fluid iscompressed and further warmed after flowing through the second heatexchanger and before returning through the first heat exchanger.
 60. Thevessel of claim 42, wherein the power generator selectively: providespower to propel the vessel when the natural gas is stored in thecontainment structure; and provides power to the gas processing facilitywhen the natural gas is being cooled or heated.
 61. The vessel of claim60, further comprising: an ancillary compressor for circulating andcooling the heat exchanger fluid while the vessel is transporting theLNG in order to recondense any natural gas that becomes vaporized duringtransport or maintain cold temperatures in the gas processing facility.62. The method of claim 59, wherein the heat exchanger fluid that coolsthe natural gas and the heat exchanger fluid that heats the natural gasare at least partially different.
 63. A method for transportingliquefied natural gas on a marine vessel, comprising: providing a gastransfer system for the vessel, the gas transfer system receivingsubstantially raw fluids from an offshore natural gas production system;providing a fluid processing system for separating produced gas from anyother produced fluids; on-loading the fluids produced from the naturalgas production system; providing a gas processing facility on the vesselfor converting the produced gas into liquefied natural gas; flowing thenatural gas through the gas processing facility so as to cool thenatural gas from its ambient temperature, to a lower temperature wherethe natural gas is in a substantially liquefied phase; providing acontainment structure on the vessel for containing the liquefied naturalgas during transport; and heating the liquefied natural gas on thevessel so as to reconvert it back into a substantially gaseous phase.64. The method of claim 63, further comprising the step of: providing aseparate containment structure on the vessel for containing any producedliquid hydrocarbons during transport.
 65. The method of claim 63,wherein the gas is offloaded at an export location into a gas storagedevice.
 66. The method of claim 65, wherein the gas storage device is anunderground salt dome gas storage cavern.